US7221158B1 - Permeability determinations from nuclear magnetic resonance measurements - Google Patents
Permeability determinations from nuclear magnetic resonance measurements Download PDFInfo
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- US7221158B1 US7221158B1 US11/299,985 US29998505A US7221158B1 US 7221158 B1 US7221158 B1 US 7221158B1 US 29998505 A US29998505 A US 29998505A US 7221158 B1 US7221158 B1 US 7221158B1
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
- G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
- G01V3/32—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with electron or nuclear magnetic resonance
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- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N24/00—Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects
- G01N24/08—Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects by using nuclear magnetic resonance
- G01N24/081—Making measurements of geologic samples, e.g. measurements of moisture, pH, porosity, permeability, tortuosity or viscosity
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- This invention relates broadly to methods for investigating subsurface earth formations. More particularly, this invention relates to methods of determining the permeability of an earth formation utilizing information obtained from a nuclear magnetic resonance (NMR) tool.
- NMR nuclear magnetic resonance
- permeability is generally considered a fundamental reservoir property, the determination of which is at least equal in importance with the determination of porosity, fluid saturations, and formation pressure.
- cores of the formation provide important data concerning permeability.
- cores are difficult and expensive to obtain, and core analysis is time consuming and provides information about very small sample volumes.
- cores when brought to the surface, may not adequately represent downhole conditions.
- in situ determinations of permeability that can quickly provide determinations of permeabilities over large portions of the formation are highly desirable.
- NMR nuclear magnetic resonance
- hydrogen in a bound or “irreducible” fluid typically has a spin-lattice relaxation time (T 1 ) in the milliseconds to tens of milliseconds, while free or producible fluid has a T 1 in the range of tens to hundreds of milliseconds.
- T 1 spin-lattice relaxation time
- free or producible fluid has a T 1 in the range of tens to hundreds of milliseconds.
- NMR tools function on the principle that the nuclei of elements such as hydrogen have an angular momentum (“spin”) and a magnetic moment.
- the nuclear spins will align themselves along an externally applied static magnetic field which may be applied by the NMR tool.
- the equilibrium situation can be disturbed by a pulse of an oscillating magnetic field provided by the NMR tool which tips the spins away from the static field direction. After tipping, two things occur simultaneously.
- T 1 spin-lattice relaxation time
- spin—spin relaxation time also associated with the spin of molecular nuclei.
- T 2 spin—spin relaxation time
- spin—spin relaxation time T 2
- T 1 spin—spin relaxation time
- all the spins are pointed in a common direction perpendicular to the static field, and they all precess at the Larmor frequency.
- each nuclear spin precesses at a slightly different rate.
- T 1 the spins will no longer be precessing in unison.
- T 2 * When this dephasing is due to static field inhomogeneity of the apparatus, the dephasing is called T 2 *. When it is due to properties of the material, the dephasing time is called T 2 . For rocks, T 2 is generally approximately one-half of T 1 .
- CPMG Carr-Purcell-Meiboom-Gill
- the CPMG sequence is a well-known sequence of pulses which cancel out the effect of the apparatus-induced inhomogeneities and permit a determination of dephasing due to material properties; i.e., a measurement of T 2 .
- Modifications to the CPMG sequence such as set forth in previously incorporated U.S. Pat. No. 5,023,551 to Kleinberg et al. have been utilized to improve thereupon.
- M(t) is a function of porosity ⁇ , the observed T2 decay T 2o , and a probability density function g 0 of the distribution of T2 relaxation in the rock pores contributing to the signal.
- g 0 the probability density function of the distribution of T2 relaxation in the rock pores contributing to the signal.
- the porosity ⁇ can be calculated.
- One manner of correcting for the problem of measuring permeability in the presence of water and oil is to generate an indication of the T2 signal, and to partition the signal via a cutoff time (e.g., 33 milliseconds) with the T2 signal prior to the cutoff time being considered related to the bound water.
- Another object of the invention is to provide methods of accurately determining permeability in oil zones.
- a drawdown permeability determination is made at a first location using a borehole tool such as the MDT, and T 2oc values generated by an NMR tool are utilized to generate permeability determinations for other locations of similar lithology (e.g., in the same stratum) as the first location.
- the generated permeability determinations may take the form of a continuous permeability log of the stratum, strata or lithology of interest.
- the T 2oc value generated from measurements made by the NMR tool at the location of an MDT drawdown test is used in conjunction with the MDT drawdown permeability k dd to provide a value for the surface relaxivity ⁇ .
- the surface relaxivity is then used in conjunction with T 2oc values generated from the NMR tool measurements at other locations of similar lithology to find the permeability k at those other locations of similar lithology.
- the single phase permeability may be used in conjunction with the T 2oc value generated from measurements made by the NMR tool at the MDT test location to provide a value for the surface relaxivity ⁇ .
- the surface relaxivity may then be used in conjunction with T 2oc values generated from the NMR tool measurements at other locations of similar lithology to find the permeability k at those other locations of similar lithology.
- a critical percolation probability for water-occupied pores is used together with other information and/or assumptions in order to permit a determination of the critical observed T 2 for pores governing water mobility T 2woc .
- T 2woc and the effective permeability to water as determined from the single probe MDT a continuous log of the effective permeability to water k o ew in the lithology stratum of interest can be generated.
- the T 2woc value generated from measurements of the NMR tool at the location of an MDT drawdown test is used in conjunction with the MDT drawdown permeability to provide a value for the surface relaxivity p.
- the surface relaxivity is then used in conjunction with T 2oc values generated from the NMR tool determinations at other locations of similar lithology to find the single phase permeability k at those other locations of similar lithology, even though two immiscible phases are present.
- single phase permeability is determined by an NMR tool even in the absence of draw-down permeability data, provided a value for the surface relaxivity is known a priori for a region of interest.
- the fourth embodiment utilizes many of the aspects of the third embodiment.
- FIG. 1 is a flow chart illustrating a method of estimating a critical percolation probability p c and a rock structure geometric factor ⁇ .
- FIG. 2 is a flow chart illustrating a first embodiment of a method for determining formation permeability utilizing an NMR tool.
- FIG. 3 is a flow chart illustrating a second embodiment of a method for determining formation permeability utilizing an NMR tool.
- FIG. 4 is a flow chart illustrating a third embodiment of a method for determining formation permeability utilizing an NMR tool.
- a highest or first order term of the permeability may be defined by the most resistant pore in the least resistant path.
- the permeability from point A to point B in the rock is controlled by which of the connecting pathways through the rock has the largest pores (i.e., the least resistant path). The smallest (i.e., most resistant) pore in that pathway acts as a constriction to the pathway.
- T 2 ⁇ o 1 T 2 ⁇ b + ⁇ l ( 1 )
- T 2b is the bulk transverse relaxation of the fluid.
- the magnetization relaxation in each pore behaves as exp( ⁇ t/T 2o ).
- T 2i T 2i
- M(t) to calculate g o (T 2o )
- the g o distribution is used to compute a permeability measure. Little distinction is made between T 2i and T 2o because T 2b is a few times larger than the observed T 2i especially in medium to low permeability sandstones.
- n l (l) the number probability density function which is derived according to
- n l ⁇ ( l ) g l ⁇ ( l ) / V ⁇ ( l ) ⁇ 0 ⁇ ⁇ g l ⁇ l ⁇ V ⁇ ( l ) ⁇ d l , ( 8 ) where it is assumed that a single length scale parameter l determines the volume of a pore V. Given the number probability density function, the critical length scale that is important for computing permeability can be estimated.
- the critical length scale, denoted l c will be the most resistant connection in the least resistant pathway, and is given by the smallest pore size within the set of largest pore sizes constituting the fraction equal to critical percolation probability p c .
- V(l) volume of a pore
- V(l) volume of a pore
- ⁇ is a geometric factor discussed in detail below. If the volume contained in the pore throats is neglected, and it is assumed that the nodes are the pores, ⁇ will have a value of three for spherical pores. Given a monotonic mapping between pore sizes and the throat sizes associated with the pore, p c should correspond to that of the site percolation problem. Since the observed magnetization is often transformed to g o (T 2o ), g o can be used to compute T 2oc (which is the critical T 2o ) according to
- Equation (10) values must be chosen for p c and ⁇ .
- the critical percolation probability p c changes with lattice type, and is known to range from approximately 0.2 for an FCC (face centered cubic) lattice to approximately 0.3 for a simple cubic lattice.
- the value ⁇ may vary from 0 to 3. Ramakrishnan, T. S., et al., “Two-Phase Distribution in Porous Media: An Application of Percolation Theory”, Int. J. Multiphase Flow 12(3), p 357–388 (1986).
- the cementation exponent m may be assumed to increase monotonically with p c , and be fairly independent of g l and ⁇ .
- the residual oil saturation (S or ) increases with both ⁇ and p c . Residual oil saturation also changes with g l .
- S or , m and M(t) are treated as measured quantities, with M(t) being measured by an NMR tool, S or being obtained from any of several tools such as the MSFL or MCFL (trademarks of Schlumberger), and m being obtained e.g., from core measurements.
- M(t) being measured by an NMR tool
- S or being obtained from any of several tools such as the MSFL or MCFL (trademarks of Schlumberger)
- m obtained e.g., from core measurements.
- the range for m is fairly narrow; typically between 1.7 and 2.
- g o and g wo may be parametrized and optimized as well.
- T 2oc may be derived, as will be discussed in detail hereinafter.
- p c is calculated using m and parameter(s) ⁇ , where any simple mathematical correlation may be assumed such that m increases with p c and the parameters of the fit are ⁇ .
- P the percolation probability
- p c it can be assumed that the percolation probability P is known.
- p c , T 2oc , and g o using equation (10), a value for ⁇ can be calculated. From ⁇ , P and g o , an estimate of S or may be obtained from a percolation-like model.
- each rock will have its own value of m, g o , ⁇ , and S or , but the functional relationships for p c versus m, and for S or in terms of p c , g o , and ⁇ are expected to be universal.
- equation (10) permits a calculation of T 2oc .
- T 2ic the intrinsic critical T 2
- T 2 ⁇ ic T 2 ⁇ oc ⁇ T 2 ⁇ b T 2 ⁇ b - T 2 ⁇ oc . ( 11 )
- Equation 12 Equation 12 becomes
- equation (13) which relates the permeability k to the surface relaxivity and the critical observed T 2 (T 2oc c) permits a determination of permeability utilizing an NMR tool in a different manner than previously conducted in the art.
- T 2oc c the critical observed T 2
- Permeability determinations obtained from drawdown tools may be used to calibrate measurements made by NMR tools because the length scale of investigation of a drawdown tool is typically comparable to the length scale of investigation of an NMR measurement (e.g., a radius of investigation of between 2 and 5 cm).
- a calibration value for ⁇ may be obtained by rearranging equation (13) to solve for surface relaxivity ⁇ , and by substituting the drawdown permeability k dd for k, such that
- the NMR determinations can be utilized to provide a continuous log of permeability for that lithology by finding T 2oc and utilizing equation (13). It will also be noted that equation (14) can be rewritten to placed in terms of T 2ic instead of T 2oc (and T 2b ).
- a multiprobe drawdown tool can be utilized to provide single phase permeability from multiprobe pressure data.
- the NMR measurement is in a zone with water and trapped hydrocarbon (where filtrate invasion from a water-based mud has displaced oil and trapped residual oil).
- the corresponding T2 distribution for a water saturated rock cannot be inferred completely. Therefore, an understanding of the NMR response in such an environment is needed.
- M o (t) M o (t) of the crude oil.
- M o (t) can be represented in terms of a finite number of exponentials:
- a ko is an oil constant for the k'th exponential
- T 2bok is the spin—spin relaxation time of bulk oil for the k'th exponential.
- the number N o should be small (e.g., 1 to 3). Then the observed magnetization in the presence of trapped hydrocarbon is
- the first term of the right side of equation (16) is the contribution by protons in water
- the second term of the right side of equation (16) is the contribution of the bulk relaxation of oil.
- T 2oc max arg ⁇ g wo ( T 2o ) ⁇ : g wo >0 (17)
- the inversion for g wo is susceptible to spreading due to finite signal to noise ratio and the ill-conditioned nature of the inversion problem.
- available resistivity data for S or may be utilized.
- any error in the characterization of oil relaxation should not cause significant errors in T 2oc by using an x somewhat smaller than unity.
- one may allow for progressively smaller noise in the data, estimate T 2oc successively, and extrapolate for T 2oc in the limit of zero noise.
- the surface relaxivity ⁇ can be calibrated using the horizontal dual probe permeability k hdp from a dual probe interpretation (see Goode, P. et al., SPE Formation Evaluation 11, p 31–40 (1996) and modifying equation (14) according to:
- a dual-packer module may be used, and the single phase horizontal permeability interpretation of the packer or the packer-probe combination may be substituted for k hdp .
- the simplest solution is to average the NMR permeability-layer thickness product as given by equation (20) and then compare it with the MDT values. To do this, the layer thicknesses should be known, and ⁇ should be assumed to be constant over the interval.
- k 0 rw can be calculated as a function of the critical radius and the formation factor in a mixed saturation state according to:
- l wc is the volume to surface area of the most resistant pore in the least resistant path among the pores containing bulk water (as opposed to thin films of water)
- F w is the formation factor that may be approximated through the Archie relation
- a critical percolation probability for the water-occupied pores may be defined as p cw by modifying equation (10) according to
- p c ⁇ ⁇ T 2 ⁇ ⁇ ⁇ oc T ⁇ 2 ⁇ ⁇ oc ⁇ T 2 ⁇ ⁇ o - v ⁇ ( T 2 ⁇ ⁇ b - T 2 ⁇ ⁇ o ) v ⁇ g ⁇ ⁇ ⁇ o ⁇ ( T 2 ⁇ ⁇ o ) ⁇ ⁇ d T 2 ⁇ ⁇ o ⁇ 0 T 2 ⁇ ⁇ oc ⁇ T 2 ⁇ ⁇ oc - v ⁇ ( T 2 ⁇ ⁇ b - T 2 ⁇ ⁇ o ) v ⁇ g ⁇ ⁇ ⁇ o ⁇ ( T 2 ⁇ ⁇ o ) ⁇ ⁇ d T 2 ⁇ ⁇ o .
- this lattice represents the percolating water cluster.
- the first color members are voided out and presumed nonexistent;
- Equation (29) shows that NMR and MDT data influenced by the presence of two immiscible phases can be used to determine single phase permeability.
- equation (29) can be used provided that values of ⁇ are known a priori for the region of interest.
- the estimate using equation (29) takes into account the network physics. Indeed, in contrast to the methods of the prior art that are hindered by the presence of hydrocarbon, the present invention takes full advantage of the basic physics of the problem to obtain the correct T 2oc to be used in the permeability determination. In many ways, the interpretation is actually facilitated by the presence of hydrocarbon, because the estimation procedure for T 2oc requires only the known bulk relaxation characteristics of oil.
- a permeability log along a formation traversed by a borehole More particularly, as seen in FIG. 2 , and with respect to water zones of the formation, at 102 data from a drawdown tool such as the MDT tool and from an NMR tool such as the CMR or MRX is obtained.
- the information from the NMR tool is indicated as M(t), and this information may be more or less continuous along the length of the borehole or in the zones of interest.
- the NMR derived measurement M(t) is obtained.
- a value for g o (T 2o ) can be obtained using equation (7).
- values for ⁇ and p c are selected.
- the drawdown permeability k dd for the depth D i is obtained from the drawdown tool
- the porosity for the depth D i is obtained from previous information, from other borehole tools, or from the NMR or drawdown tools
- values for T 2b and m are selected.
- the value for T 2b for water is typically known from literature, while m is either fixed or selected to ensure consistency with p c as previously discussed with reference to FIG. 1 .
- the surface relaxivity ⁇ is computed at 116 using equation (14).
- steps 104 – 120 are conducted only once, and there will be no averaging at step 122 .
- the permeability k for any depth of similar lithology is obtained at 124 utilizing the NMR data and equation (13) for each depth of interest. For example, if depth D i at which MDT data was obtained was in a particular stratum of the earth formation, permeability determinations are made not only for depth D 1 , but at multiple locations (e.g., D 1-1 , D 1-2 , D 1-3 , D 1-4 . . .
- the NMR measurements M(t) are used to calculate values of T 2oc using equation (10), and those values are used in conjunction with the surface relaxivity ⁇ for that lithology in equation (13) to obtain determinations of permeability k which may be displayed in log format.
- the first order or primary consideration is whether the zones have similar mineralogy; e.g., limestone, sandstone, dolomite, and relative clay components.
- a second order consideration would be the deposition environment. Information regarding mineralogy may be obtained using downhole tools such as the ECS (Elemental Capture Sonde) tool or the FMI borehole imaging tool (ECS and FMI being trademarks of Schlumberger).
- FIG. 3 a second embodiment of the invention is seen with respect to oil zones of the formation where horizontal permeability data is available from either a dual probe drawdown tool, or a packer or packer-probe tool (hereinafter referred to as MDT data for this embodiment).
- MDT data and data from an NMR tool such as the CMR or MRX is obtained.
- the data from the MDT is indicated as being from a single location in an oil zone in the formation, while the information M(t) from the NMR may be more or less continuous in the zone of investigation of the MDT (i.e., at various depths Z i which are typically anywhere between 0.1 and 0.5 meters apart over the expected depth of investigation of the MDT multiprobe tool).
- the NMR derived measurement M(t) is obtained.
- porosity ⁇ and residual oil saturation S or data is provided for that depth.
- the data provided at 205 may be obtained from one or more of (i) the MDT tool, (ii) other tools which measure formation resistivity and/or porosity, (iii) the NMR tool, or (iv) previously obtained knowledge of the formation.
- a value for g wo (T 2o ) is obtained using equation (16). From g wo (T 2o ), using either equation (17) or equation (18), a determination of T 2oc is made at 210 .
- the NMR depth index i is increased and at 220 the increased index is compared to N to see whether all NMR data for the depth of interest have been analysed. If not, the method returns to step 204 and cycles through until all data samples have been analysed. If so, at 221 a , the horizontal dual probe permeability k hdp for the depth Z i (or, in the case of a dual-packer module or a packer-probe combination, a single phase horizontal permeability interpretation for that depth) is obtained from the MDT. At 221 b , values for T 2b and m are selected.
- T 2b for water
- m is either fixed or selected to ensure consistency with p c as previously discussed with reference to FIG. 1 .
- the surface relaxivity ⁇ is computed at 222 .
- the permeability k for the depths Z i through Z N are individually obtained at 224 using equation (20) for each depth with ⁇ being the porosity for that depth and the observed critical T 2 being the T 2oc as calculated at step 210 according to equations (17) or (18) for that depth.
- the calculations of permeability may then be displayed in log format as is well known in the art.
- the NMR measurements M(t) are used to calculate values of T 2oc using equation (17) or equation (18), and those values may be used in conjunction with the surface relaxivity ⁇ for that lithology in equation (20) to obtain determinations of permeability k which may be displayed in log format.
- FIG. 4 a third embodiment of the invention is seen with respect to oil zones of the formation where drawdown data is available from a single probe tool.
- data from a drawdown tool such as the MDT tool and from an NMR tool such as the CMR or MRX is obtained.
- the information from the NMR tool is indicated as M(t), and this information may be more or less continuous along the length of the borehole or in the zones of interest.
- the NMR derived measurement M(t) is obtained.
- porosity ⁇ and residual oil saturation S or data is provided for that depth.
- the data provided at 305 may be obtained from one or more of (i) the MDT tool, (ii) other tools which measure formation resistivity and/or porosity, (iii) the NMR tool, or (iv) previously obtained knowledge of the formation.
- M(t) a value for g wo (T 2o ) can be obtained using equation (16).
- g wo (T 2o ) using either equation (17) or equation (18), a determination of T 2oc is made at 310 .
- a value for p cw is obtained either based on other known information, or based on default values, or based on an estimate of p c and the use of equations (24) and (26).
- An estimated value for p c (and ⁇ ) can be made using the method of FIG. 1 , or based on other known information, or based on default values.
- the drawdown permeability k 0 ew for the depth D i is obtained from the drawdown tool, and at 314 , values for T 2b and m are selected.
- the value for T 2b for water is typically known from literature, while m is either fixed or selected to ensure consistency in p c as previously discussed with reference to FIG. 1 .
- the surface relaxivity ⁇ is computed at 316 using equation (28).
- steps 304 – 320 are conducted only once, and there will be no averaging at step 322 .
- the effective permeability to water k 0 ew may be generated for all depths D i using the NMR data for that depth and utilizing equation (28) and the determinations (i.e., T 2oc ) at that depth utilized in equation (28). If desired, k 0 ew may be displayed as a continuous log.
- the permeability k is found for each depth D i using equation (29). Further, determinations of permeability for locations of similar lithology are obtained at 324 utilizing the NMR data and equation (29) for each depth of interest. For example, if depth D 1 at which MDT data was obtained was in a particular stratum of the earth formation, permeability determinations are made not only for depth D 1 , but at multiple locations (e.g., D 1-1 , D 1-2 , D 1-3 , D 1-4 . . .
- the NMR measurements M(t) are used to calculate values of T 2oc using equation (17) or equation (18), and those values are used in conjunction with the surface relaxivity ⁇ for that lithology in equation (29) to obtain determinations of permeability k which may be displayed in log format.
- the present invention permits determinations of surface relaxivities for different lithologies.
- the invention allows the calculation of permeability at points along the formation for which NMR tool measurements have been made but where no drawdown information is available.
- drawdown tools should be understood to be any tool which permits fluid to flow into and/or out of the tool, and therefore, out of and/or into the formation.
- drawdown tools shall be understood to include injection type tools.
- drawdown tools are used to obtain in situ permeability determinations
- other means could be utilized to generate permeability determinations for calibration.
- either of these, or any other in situ permeability determination could be utilized to generate permeability determinations for calibration with the NMR determinations.
- equations are generally zeroth order expressions, and the equations could be modified to add first and higher order corrections.
- equations (1) and (2) could be modified to account for diffusion in the pore.
- equations (13) and (14) could be modified to account for first order changes which might affect the constant, or might provide additional parameters to the equation.
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Abstract
Description
where T2b is the bulk transverse relaxation of the fluid. The magnetization relaxation in each pore behaves as exp(−t/T2o).
The volume probability density function with respect to/denoted as gl(l) is
∫0 ∞ g l(l)dl=1 (3)
Similarly, gi(T2i) is the probability density function (pdf) with respect to T2i. It follows then that
With respect to the observed relaxation times, the pdf go satisfies
∫0 ∞ g o(T 2o)dT 2o=1 (5)
It should be noted that go(T2o)=0 ∀T2o>T2b. It can also be seen that
M(t)=φ∫0 ∞ g o(T 2o)exp(−t/T 2o)dT 2o (7)
The typical processing procedure is to use M(t) to calculate go(T2o), an algorithm for which is provided by U.S. Pat. No. 5,363,041 to Sezginer. Presently, the go distribution is used to compute a permeability measure. Little distinction is made between T2i and T2o because T2b is a few times larger than the observed T2i especially in medium to low permeability sandstones. Generally, however, one needs to at least translate go to gl through Equation 6 before applying existing correlations such as those proposed by Kenyon, W. E. et al., “A Three-part Study of NMR Longitudinal Relaxation Studies of Water-Saturated Sandstones”, SPE Form. Eval. 3, p 662–636 (1988), although this is not explicit in their correlation.
where it is assumed that a single length scale parameter l determines the volume of a pore V. Given the number probability density function, the critical length scale that is important for computing permeability can be estimated. The critical length scale, denoted lc will be the most resistant connection in the least resistant pathway, and is given by the smallest pore size within the set of largest pore sizes constituting the fraction equal to critical percolation probability pc. Although not stated explicitly, this connection was first used in Macmullin, R. B. et al., “Characteristics of Porous Beds and Structures”,
p c=∫l
(see, e.g., Macmullin, R. B. et al.—previously cited; Johnson, D. L. et al., “New Pore-Size Parameter Characterizing Transport in Porous Media”, Phys. Rev. Lett. 57(20), p 2564–2567 (1986); Ramakrishnan, T. S. et al., SPE49502 (1998)), where r is a permeability determining length scale, the following is obtained:
where F is the formation factor defined according to F=1/φm. The proportionality constant of ⅛ may need minor adjustments for a given region or lithology, but in general, the result finds wide applicability. As shall be seen, the calibration methods of the invention compensate for any inaccuracies in this value. In terms of T2oc, Equation 12 becomes
where it is seen that the permeability is defined in terms of the surface relaxivity ρ. It should be appreciated that the numerical proportionality constant (⅛) may be lumped with ρ2 in a calibration process as discussed hereinafter. It will also be appreciated that since T2ic is a function of T2oc (and T2b), equation (13) can be rewritten in terms of T2ic.
where the porosity term replaces F according to F=1/φm as previously stated. In the absence of additional information, the cementation factor m may be assumed to equal 2. Once a calibration for surface relaxivity ρ is obtained, it may be used as the value for similar lithologies along the wellbore. Thus, according to the invention, once a value for ρ is obtained for a particular lithology, the NMR determinations can be utilized to provide a continuous log of permeability for that lithology by finding T2oc and utilizing equation (13). It will also be noted that equation (14) can be rewritten to placed in terms of T2ic instead of T2oc (and T2b).
where ako is an oil constant for the k'th exponential, and T2bok is the spin—spin relaxation time of bulk oil for the k'th exponential. In order that the resolution of the relaxation behavior be robust, the number No should be small (e.g., 1 to 3). Then the observed magnetization in the presence of trapped hydrocarbon is
where gwo is the volume probability density function of water occupied pores with respect to T2o. Those skilled in the art will appreciate that the first term of the right side of equation (16) is the contribution by protons in water, and the second term of the right side of equation (16) is the contribution of the bulk relaxation of oil. Based on the water-oil phase replacement physics as described above, the critical observed T2 is
T 2oc=max arg{g wo(T 2o)}:g wo>0 (17)
In practice, the inversion for gwo is susceptible to spreading due to finite signal to noise ratio and the ill-conditioned nature of the inversion problem. For this reason, a preferable choice is to estimate T2oc from
x=∫ 0 T
where x is a number close to 1 (e.g., 0.9). In the application of equation (16), available resistivity data for Sor may be utilized. Alternatively, Sor may be permitted to float as a part of an inversion. In either case, any error in the characterization of oil relaxation should not cause significant errors in T2oc by using an x somewhat smaller than unity. Alternatively, during the processing for gwo, one may allow for progressively smaller noise in the data, estimate T2oc successively, and extrapolate for T2oc in the limit of zero noise.
As before, the calibrated value of this ρ can be used to determine a NMR based permeability in other lithologically similar regions according to
By definition, lwc is the volume to surface area of the most resistant pore in the least resistant path among the pores containing bulk water (as opposed to thin films of water), and Fw is the formation factor that may be approximated through the Archie relation
Often, m is equated to n if no other information is available. The difficulty therefore lies in determining lwc.
It should be noted that the entire water occupied network has pores up to T2oc, the point at which oil is completely trapped. In this network, the above equation allows for a calculation of T2woc, which in turn determines the critical pore size governing water mobility.
where z is the coordination number. At residual oil condition, the coordination number of the water percolating network can be approximated as z(1−1/(z−1))=z(z−2)/(z−1). For this new coordination number, replacing z in equation (24) with z(z−2)/(z−1), an estimate for pcw is
Clearly, the Bethe lattice result cannot be applied to the well known 3D lattices in terms of the coordination number. But, the ratio pcw/pc of the Bethe lattice should be applicable. Then,
pcω≈1.1pc (27)
Even for a simple cubic lattice, pcw is expected to be only 30% larger than pc. Therefore, pcw is expected to lie in the range of 0.2 to about 0.4.
Given that k0 ew is known from single probe MDT data, a calibration for ρ is obtained, which may then be used to generate a continuous log for k0 ew. More importantly, since T2oc has also been generated in this process, it is possible to compute single phase permeability from NMR measurement in a two-phase environment through
Equation (29) shows that NMR and MDT data influenced by the presence of two immiscible phases can be used to determine single phase permeability.
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